Abstract:
The common application of geochemical kinetic is to predict temperature, time and depth of hydrocarbon generation in Basin and petroleum system modeling. The goals of the present study is comparing the kerogen and bitumen (asphaltenes) bulk kinetic parameters in the Kazhdomi Formation from Gachsaran oil field, and the possibility of its pollution by the hydrocarbons generated from the deeper formations which might have migrated to the studied formation. Generally, in order to perform kinetic studies, first the samples should be analyzed by suitable Laboratory Pyrolyzer. Then, the obtained data is used as input of various kinetic modeling software to determine and optimize the kinetic parameters, ultimately in the petroleum system modeling, the kinetic parameters unit is changed to geological time scale to predict the time and depth of hydrocarbon generation. In order to achieve the objectives of this study, three cutting samples from Kazhdumi Formation of well No. 368 in Gachsaran oil field were selected. The samples were pyrolyzed at three different heating rates (5, 15 and 25℃/min) using Rock-Eval pyrolysis. In order to determine the kinetic parameters (activation energy and frequency factor), the obtained data were optimized by Optkin software. Finally kinetic parameters were used as input of PetroMod software in order to perform kinetic modeling (Hydrocarbon generation rate and Transformation ratio curves) and 1D modeling at geological condition of 1.5℃⁄My. Based on maximum temperature of hydrocarbon generation (Tmax) results, the kerogen already reached the matured stage. The maximum value as well as the distribution of the activation energy, also the correlation between the transformation ratio and hydrocarbon generation rate curves of asphaltene samples, indicate the uniformity and structural similarity of the samples in the studied Formation On the other hand, based on the distribution pattern of activation energy, despite the uniformity of kerogen type (kerogen type II), the differences in kinetic parameters indicate that the samples in various depths are not identical. The transformation ratio and hydrocarbon generation rate curves of asphaltene samples has no direct correlation. It can be concluded that this cases support probability of hydrocarbon migration from deeper formations. Finally it can be concluded that, the obtained 1D modeling results from kerogen samples strongly suggest to use immature kerogen for kinetic studies.

 The Azadegan oil field is one of the world's developing giant oil field with about 900 km2 extent is located at 80 km west of Ahvaz City. The main goals of this study are Geochemical comparison of light oil in Fahlian-Sarvak carbonate reservoirs, as well as determination of possible source rock and their’s maturity in Azadegan oil field; Abadan Plain. In this study 55 cutting samples from possible source rock formations (Kazhdumi, and Sargelu) as well as 6 oil samples from Fahlian and Sarvak reservoirs of Azadegan oil-field have been investigated geochemically. Total organic carbon versus S1 + S2 reveals that Sargelu and Kazhdumi Formations have high potential and remaining formations have low potential for hydrocarbon generation. Results were plotted on OI versus HI diagram show that Kazhdumi Formations type II kerogen to type III is dominant, Sargelu Formation has type III kerogen
Bimodal and multimodal chromatogram of, Sarvak and Fahlian reservoirs show several source for this studied reservoir’s oil. For all of the studied oil with increasing depth and moving to north of oil field maturity increased. Low abundance for mortans, Sterane/Hopane and Ts/Tm ratios, also low percentage Sterane and tricyclic terpanes to pentacyclic terpanes shows the source rock for studied reservoir’s oil enriched by organic matter from bacterial source. High amount of C22t/C21t, low value of C24t/C23t, Diasterane/Sterane ratio Vs C29/C30 Hopane and C27 Dia/Dia+Reg Ratio Vs Pr/Pr+Ph shows the source rock for, Sarvak and Fahlian reservoirs derived from carbonaceous - marl source rock in marine envoirment, but effect of carbonate to marl is much.
Pr/nC17 Vs depth and Pr/n-C17 Vs Ph/n-C18 diagrams, C29/C30 Hopane and C35/C34 Homohopane ratios also absence of 25 Nor Hopanes indicated lack of biodegradation in reservoir’s oil in the studied oil field. Presence of tricyclic terpanes and Ts, ETR value, Oleanane/(Oleanane+Hopane), C28/C29 and 1,3,7- trimethylnaphtalenes/1,2,7 Trimethylnaphthalene Ratios also δ13C Vs Pr/Ph diagram shows source rock for, Sarvak and Fahlian reservoirs is carbonaceous with Jurassic to lower Cretaceous. Isomerization and epimerization ofC32-hopane and C29-Sterane shows oil in Fahlian reservoir located in early oil window also oil in Sarvak reservoirs are in early and middle Peak Oil Window respectively. According to the same possible source rocks and lack of secondary affecting processes, can be conclude that heavy oil in Fahlian and Sarvak reservoirs due to oil generation from Kazhdumi formation and charging these reservoirs. bimodal Chromatogram possible charging by Kazhdumi formation shale’s, lighting oil in this reservoir can be related to absorbing polar component by clays associated with sandstone and caused that produced oil depleted from this component and had high API.

Khaviz and Mansourabad oil fields are located in the southern Dezful embayment with directional Northwest to Southeast. These two fields are separated from each other due to the activity of Tashan fault. The fault activity has caused the Khaviz field to be higher than Mansourabad. So In this study, in order to investigate the effect of fault activity on the geochemical and thermal maturity of Pabdeh formation as a probable source rock in Khaviz and Mansourabad oil fields, using Rock-Eval Pyrolysis analysis, vitrinite reflectance and modeling by Petromod 2011.1 software. The results of the Rock-Eval Pyrolysis analysis of the Pabdeh Formation are divided into three zones, which are upper and lower zones of lower TOC with Marl and limeston lithology, and the middle zone with is more TOC with the shale and shalylimeston lithology. Total organic carbon (TOC) of Pabdeh Formation at both fields was determined to be 6.46-0.21% wt, and the type II kerogen and a mixture of II/III. Tmax and PI index derived from Rock-Eval and also the data of the measured vitrinite reflection indicate the maturity of the Pabdeh Formation in Khaviz field in the immature stage and in Mansourabad field in the early oil window. The results of reconstruction burial history well NO. 2 of Khaviz field, the layers were eroded after uplifting, so that erosion caused Asmari Formation outcrops on the surface. Therefore, the increasing process of maturation of Pabdeh Formation has been reduced and stopped in the immature stage. But in the well No. 11 of Mansourobad field the layers after folding with erosion due increasing thickness of Gachsaran Formation and increasing the rate of maturation, and this put early oil window. In the 2D modeling, according to Easy Ro% modeling, Pabdeh Formation in Mansourabad and parts of Khaviz fields, this formation has entered into the oil window in the period of 9-10 million years ago, which is associated with sedimentation of the Mishan Formation and after sedimentation of the Aghajari Formation during folding the top formations, the increasing rate of maturation is reduced. In this model, the temperature of Pabdeh Formation in the present day of Khaviz field 33cᵒ and Mansourabad field was 110 cᵒ and value the transformation ratio (TR) at 0.03% in Khaviz field and 10% in the Mansourabad anticline and up to 35% in the limb anticline and syncline. According to the amount TR of Mansourabad field, Pabdeh Formation in the anticline and syncline limbs have expelled its oil and Cover a little contribution at oil reservoirs of Mansourobad field. But however, in the Khaviz field, the TR ratio is very low, which indicates that Pabdeh Formation is not in maturity condition. After calibration, the models of the calculated heat flow in the Khaviz and Mansourabad fields vary in the range of 43 to 47mW / m2

The saturated water factor is one of the most important petrophysical parameters of hydrocarbor reservoirs. The most common formula used for calculation of water saturation is Archie’s equation. Cementation factor (m) plays such an important role, in this regard, that a slight change in this factor causes considerable changes in water saturation. The value of m depends on the amount and type of porosity, permeability, rock texture, water salinity of formation and other cases; and it cannot be considered fixed. The main purpose of this research is determination of Archie’s factor (m) in the Asmari reservoir, well 3 of Ramin oil-field. Ramin oilfield is located in Dezful embayment and 30 kilometers north of Ahwaz and northwest of Maroon oilfield. At first, using the existing porosity and permeability data for Well 3 and applying the flow regional index method, flow units and then cementation factor were determined. Then, using the related PHIE, DT, NPHI, RHOB, Sw and GR well loggings in Facimage section of Geolog software environment, the Asmari reservoir facies were identified with MRGC clustering method in the studied well, and in terms of quality, 9 facies were obtained. By merging the similar facies, five facies were determined which were ordered and numbered based on reservoir quality. Using the identified facies, cementation factor was also determined for each facies. In the following with drawing the diagram of effective porosity - total resistance, and examined the changing trend of water saturation (Sw) and cementation factor (m). At the end, the final model for well 3 was constructed. Examining reservoir properties for identified facies showed that the reservoir quality improves from facie 5 to facie 1. Also, the amount of cementation factor decreases from facies number 5 to number 1. These results will be useful to predict the amount of hydrocarbon in place the reservoir and to perform enhanced oil recovery studies.

To study and characterization of the Asmari reservoir fractures in one Oilfields in Dezful Embayment(Southwest of IRAN), thin sections, image logs(OBMI,UBI,EMI, and FMI) and petro physical logs were used and fractures zones in the Asmari reservoir were determined using image logs in this exploration field. The main aim of this thesis is attain to new methods, rapid and inexpensive ways, (e.g. EMI tools, velocity deviation log) to detect of fracture zones. There is observed stylolite, pores, micro fractures as open and filled in the Asmari reservoir which was also verified by indirect method, FMI. According to cores data, relative density of open fractures decreased but filled fractures increased to depth. Fractures are mainely longitudinal and latitudinal types with high angles to bedding surface. Abundance stratigraphic stylolites with increasing depth are due to compressional forces which have resulted from the weight of sedimentary strata ,The study image logs and thin sections revealed, limestone, in some cases dolomitic limestone and shale limestone with some anhydrite are the dominant lithology of Asmari formation in this well. In order to achieve the given goal; image logs in the well was processed and interpreted by GEOFRAME software and then the interpreted results of well was used to achieve more correct results in interpreting of Asmari reservoir fractures. FMI log and thin sections and cores data were indicated that the main porosity system of the reservoir is iterparticle and fractures types. The presence of oil staining in thin sections, it was revealed that the fractures are conduits to transferring the fluid.
The results show that the pore network of the reservoir is mainly consist of intergranular and fracture types, And according to oil contamination in the most of thin sections, much importance of fractures as a passageway for passing fluid was revealed. Based on the interpretation of image logs in reservoir, the main types of paleostrains are located in the (N82W, S90E) and (N80E, S88W) for the maximum and minimum strain axis respectively that is in index of Gachsaran shear zoon activation. In addition, fracture types can be estimated as fractures related to folding. Since velocity deviation log and results of differentiation method have high correspondence with image logs in determination of fractures, especially in the fractured reservoirs, image logs are a good substitute for core analysis. It is also possible to classify the fractures as folding affinity as pattern-2; i.e. longitudinal fractures. All data presented in this thesis resulted from speed deviation and FMI logs are showing noticeable positive correlation in view of fracture types and porosity system in the Asmari reservoir. Consequently, to study of fractures in the fractured reservoir, specially, image log can be a suitable alternative method to core analysis.
 

 The giant Gachsaran oil field located about 220 km southeast of Ahvaz and 65 km north of Persian Gulf. Developing the fracture systems in Asmari Formation and Bangestan Group (Ilam and Sarvak formations) as the main reservoirs of Gachsaran oil field has led to hydrocarbon migration from Bangestan reservoir to Asmari Formation. Stratigraphically, Pabdeh Formation is situated between Asmari and Bangestan reservoirs. Thus, if the heavy compounds of Bangestan reservoir oils which originates from Kazhdumi Formation precipitates in Pabdeh Formation, its kinetic parameters can be influenced by these compounds. Regarding to similarity between kinetic parameters of asphaltene and its parent kerogen, determination and comparison of kinetic parameters (activation energy and frequency factor) of kerogen and asphaltene from Pabdeh Formation in Gachsaran oil field are the main goals of this study. Determining the whole rock kinetic parameters can be useful, too. In this regard, three immature core samples from different depths of Pabdeh Formation in Gachsaran oil field were selected. The pyrolysis of the whole rock, kerogen and asphaltene samples was performed using Rock-Eval 6 instrument at three different heating rates of 5, 15 and 25 ºC/min. As well, kinetic parameters were optimized and determined using Optkin software. Kinetic modeling of the samples was performed using PetroMod software by assuming a geological heating rate of 1.5 ºC/My. Furthermore, different kinetic parameters were used in the same conceptual 1D models. Based on the results of kinetic modeling, the temperatures of the onset and the peak oil generation from the same samples using different kinetic parameters are not identical. Despite the studied samples are close together in terms of depth, variations in the onset and the peak oil generation temperatures based on the kinetic parameters of whole rock and asphaltene, unlike the kinetic parameters of kerogen, are so significant and irregular. According to the results of conceptual 1D models, the prediction of timing, location and temperature of the onset of oil generation from studied samples varies regarding different kinetic parameters. These variations based on kinetic parameters of whole rock and asphaltene, unlike kinetic parameters of kerogen, are remarkable. Obtained results from the kinetic modeling and the conceptual 1D models along with the high amounts of extracted bitumen from studied samples despite their low maturity as well as the sharp decrease in S2 parameter values of Rock-Eval pyrolysis for kerogen samples versus whole rock samples indicate that the heavy compounds of Bangestan reservoir may have been precipitated in Pabdeh Formation which in turn can influence the kinetic parameters of this formation. Consequently, using the kinetic parameters of kerogen instead of whole rock and asphaltene kinetic parameters in order to modeling the of generation from Pabdeh Formation in Gachsaran oil field is strongly recommended.

The Gulkhari oilfiled is located in the Zagros basine and southern margin of Dezful Embayment subzone. The Gulkhari oil is being produced from the limy-dolomitic strata of Asmari/Jahrum (Late Eeocen-Miocene). The trap is a high amplitude anticlinal structure, with the two subsurface anticline thrust faults in the flanks, possibaly serving as avenues to fluid migration from underlying probably source rock(s). The objective of this study is to provide information on source organic matter input, depositional conditions, maturity and the correlation between crude oils recovered from Gulkhari oilfield and kazhdumi (Albian-Cenomanian), Gurpi (Commpanian – Maastrichtian) and Pabdeh (Eocene) formations. To evaluate source rock characteristics, 15 cutting samples were analyzed using Rock-Eval pyrolysis. Based on the results, the Kazhdumi, Gurpi and Pabdeh formations, which have poor to good, fair and poor to very good source rock potential, respectively, situated in the early mature to oil window. However, 1D burial history and thermal maturity of Gl-2 well indicate that the lower of Kazhdumi formation occurs in the main oil window generation. In terms of organic matter, Pabdeh formation with kerogens of type II and II/III, while Gurpi formation contains mostly kerogens of type II and Kazhdumi samples contain I, II, III kerogens type. The investigated biomarkers indicated that the Asmari/Jahrum oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from moderately high Pr/Ph ratio (1.25-1.49), relatively low homohopane index (0.05 – 0.08), composed of regular steranes with C27>C29>C28, relatively low to moderate C27/C29 regular steranes (0.94-1.68), and the presence of tricyclic terpanes as well as low to moderate DBT/Phen ratios (0.35-1.30). Maturity estimates based on biomarker maturity parameters include C2920S/ (S+R) (0.41 – 0.53), C29ββ/ (ββ+αα) (0.49 – 0.53), C32 homohopane 22S/(22S+22R) (0.46-0.60), VRc (0.67-0.92) and VRm (0.62-0.95) indicate that these oils were generated from source rock in the early to main oil widow. Based on molecular indicators, selective source rocks have a equal level of thermal maturity (early oil window), but the Kazhdumi formation, among others has organic matter and depositional condition similar to crude oils. While the Gurpi and Pabdeh formations have marine organic matter. Therefore, the correlation between the Asmari/Jahrum oils and the kazahumi formatin is positive in the Gulkhari oilfield.

In every drilling process a lot of wastes including cuttings together with drilling muds, water and completion fluids are produced. In onshore wells these wastes are usually deposited in open pits. Regarding the types of the waste and the drilling mud (water-base or oil-base), they may a have a harmful effect on the environment and the living things. For the purpose of determining the type and the concentration of the pollutants, 16 different samples from different materials (drilling mud, mud waste, and the soil from the drilling area) were collected. One of these samples was chosen as the control sample. For the validation of the results, repetitive samples were also analyzed. The samples were analyzed by ICP-OEC for determining the concentration of heavy metals. 7 samples were also analyzed by GC-MS for measuring the amount of PAHs. The average amount of the heavy metals in the soil of the study area in comparison with the worldwide standards and soils of other oilfields was higher. The results showed that the amount of Pb, Zn, and Cu in the Ahwaz oilfield was higher than the other points. The acidity and alkalinity of the soil was also measured. The results showed that the soil is alkalified and this is mostly due to the consumption of water saturated with salt for producing drilling muds. For the determination of the degree of the pollution of heavy metals factors like geoaccumulation index (Igeo), enrichment factor (EF), Potential ecological risk(Er) , and Nemerow integrated pollution index (NIPI) were analyzed. The results showed that As, Pb, Cd, Ba, Ni, Ni, Cu, and Zn have highly polluted the region and must be controlled. To analyze the effect of heavy metals on human health, the amount of inhalation, ingestion, and dermal in two age ranges of children and adults was calculated and the results revealed that Mn had the highest amount of absorption by ingestion in both age ranges. Also regarding the USEPA standards the non-carcinogenic risk (HQ) of each metal was determined. The results showed that the amount of each single metal doesn't cause a high risk but the sum of the amount of metals (HI) is high for children. The evaluation of the carcinogenic risk revealed that the amount of As, Co, Cr, and Ni was high for children and the amount of Cd was high for adults. Statistical analysis such as the Pearson coefficient, principle component analysis (PCA), and cluster analysis (CA) determined three different sources for the pollutants. These sources were the drilling mud, the crude oil coming up with the drilling mud, and the fuel burnt by the drilling equipment. The sum of the high molecular weight (HMW) PAHs showed that 71 percent of the samples were highly polluted. The amount of low molecular weight (LMW) PAHs was lower than the amount of high molecular weight (HMW) PAHs, so the amount of non-carcinogenic compounds was higher than carcinogenic ones. Since the LMW/HMW ratio is bigger than 1, the source of these pollutants is petroleum. Statistical parameters showed that all the PAHs have a common source.

 Khoozestan province, because of having different industries faces the receipt and accumulation of a wide range of pollutants and wastes. One of the most important and active industries is drilling oil and gas wells. Marun is one of the biggest oilfields in the region. The mud used for drilling and its waste contains heavy metals and organic materials. These pollutants finally accumulate in the soil. Since soil is an important factor in human life and these pollutants harmfully affect it, it is necessary to study their concentration in the soil and also their effect on human health. In this research 12 samples from drilling mud, waste (mud + cuttings), and soil was taken from the study area and one was chosen as the control sample. The samples were prepared in the laboratory and then analyzed by ICP-OES for determination of concentration of heavy metals. The samples were also analyzed by GC-MS for measuring the amount of PAHs. For determination of the amount of the pollution of heavy metals, different factors like enrichment factor (EF), index of geoaccumulation(Igeo), pollution index(PI), and Nemerow integrated pollution index(NIPI) were analyzed. The results showed a high level of pollution for metals like Cd and Pb, an intermediate level of pollution for Mo and Zn, and a low level of pollution for Co and Cr. To analyze the effects of heavy metals on the human health, the daily amount of absorption by ingestion (ADDingestion), inhalation (ADDinhalation), and dermal (ADDdermal) was calculated for two age ranges of children and adults and the risk of non-carcinogenic (HI) and carcinogenic (RI) was measured. Zn had the highest amount of absorption by ingesting and Cr had the lowest amount by dermal. The amount of non-carcinogenic risk in all paths was high for children. In both age ranges Cr had the highest amount of carcinogenic risk and Ni had the lowest amount. The PAH analysis showed that PAHs with low molecular weight (LMW) were dominant in all samples. Also, the sum of non-carcinogenic PAHs was bigger than the carcinogenic ones. Regarding the classification of organic pollutants, the oil-base muds were highly polluted. By the comparison of the organic ratio, it was revealed that all the pollutants had an anthropogenic source. Statistical analysis such as the Pearson coefficient and principle component analysis (PCA) showed that both heavy metals and PAHs had an anthropogenic source. The pH of all samples was alkalified and since most heavy metals are not or slightly mobile in alkalified conditions, this is a reason for the accumulation of these pollutants in the soil and hence causes a higher risk for human and environmental health.

Measurement of nickel and vanadium is a rapid and reliable method for comparing oils, their source and depositional environment. The main purpose of this study is measuring the concentrations of Ni and V, their changes and the cause of these changes in Asmari and Bangestan Reservoires of Ahvaz Oilfield. The results were to detect the source of generated hydrocarbons, Interpretation of characteristics and their depositional environment. The changes were related with geological structures. In this purpose, 32 wells from Asmari and Bangestan reservoirs of Ahvaz oildField was selected and by using Atomic Absorption Spectrometry the concentration of these elements in crude oil samples were measured. Ni concentrations measured in the samples of Asmari reservoir crude oils was in the range of 7 to 46.6 ppm, the concentration of V was between 11.2 to 73.6 ppm, Ni concentration in Bangestane reservoir was in the range of 5.4 to 54.2 ppm, and the concentration of V was between 28.1 to 139.64 ppm. The average ratio of Ni /V crude oil for Asmari reservoir was 0.51 and for Bangestan reservoir 0.31. This indicates a marine environment and a reducing conditions for the reservoir rock and shows that phytoplankton Bacteria as organic matter for oil production. Regarding the average amount of Ni and V, Asmari and Bangestan reservoirs have different sources. The changes in the amount of Ni and V is a reflection of structural phenomena.around wells No. 227, 276, 363 and 365 the amount of Ni and V has decreased so this reduction could be used as a reliable method for determination of subsurface structure.

 In this study 2 sets of data were investigated by multi- criteria decision making
analysis. As the first challenge, the data of Rock Eval pyrolysis method was
evaluated using classic TOPSIS and Fuzzy TOPSIS and the states of formations were
investigated and evaluated. As the second challenge, the samples of 10 wells of
Asmari and Bangestan Reservoires in Maroon oil field were examined. The
geochemical data was analyzed based on classic TOPSIS and Fuzzy TOPSIS, and
then the priority of digging developmental wells was determined based on the data.
In Rock Eval data analysis, the results based on expert's weights in classical TOPSIS
method showed that among formations of source rock kaghdumi pabdeh and gurpi
formations were the first, second, and third priorities, respectively. The results of
data analysis using Fuzzy TOPSIS were slightly different. In geochemical data
analysis, the results based on expert's weights in classical TOPSIS revealed that well
200 of Asmari Reservoires and well 62 of Bangestan Reservoires were the first and
last priorities, respectively. The other wells including well 173, 35, 208, 41, 237, 69,
162, and 233 were placed between the first and last priority, respectively. Slightly
different results were observed in the same data analysis using Fuzzy TOPSIS
method. Finally, it is suggested that future developmental wells be dug adjacent to
the wells with the first and second priority and then other priorities be considered.
This will play an important role in production process enhancement.

 Abadan plain is located in the southwestern part of the Zagros fold and thrust-belt and also includes the northwestern part of the Persian gulf. The main goal of this study is to reconstruct the burial history and modeling the thermal maturity in an oil field in this region using Rock-Eval pyrolysis data and Vitrinite reflectance measurements. In order to accomplish that, the 1-D burial and thermal modeling was performed in 2 separate wells in both northern and southern anticlines using the Petromod software. To determine the hydrocarbon generation potential, TOC vs. S1+S2 diagram was used. It shows that Kazhdumi Formation has fair to excellent potential while Pabdeh, Gurpi and Gadvan formations has poor to good potential. Hydrogen index (HI) and Oxygen index (OI) values indicate that the type of organic matter in the Kazhdumi Formation has a wide range of variation from type-I to type-III. The organic matter of Pabdeh and Gadvan formations mainly consist of type II and III. Gurpi Formation mostly contains type-III organic matter. Plotting PI (production index) against Tmax values to determine the level of maturity of studied samples shows that most samples are located in the early oil generation window. The model output shows that in both wells, the lower and upper part of the Gadvan Formation is in the main oil generation window but Kazhdumi Formation is still in early phase of oil generation. Pabdeh and Gurpi formations in both wells are immature. Gadvan Formation cannot be considered as effective source rock due to the poor organic matter quantity and quality. In addition to Kazhdumi Formation, a main contribution in this region exists from deeper Jurassic formations (Garu and Sargelu). Deeper driling and more analytical studies can be greatly helpful.

 This study has been done to compare geochemichal and hydrocarbon production potential between A and B oil fields source rocks as the main goal. According to corrected van kerevelen diagram, Pabdeh Formation in these two oilfields has type II-III and III kerogen respectively. Kazhdomi Formation in B oilfield is in the early oil window to main oil zone and in A oilfield has entered to oil window. In A oil field Gadvan and Gurpi Formation both have type II kerogen and are located in beginning of oil window and because of low maturity cannot generate petroleum. On the basis of rock eval results, source rocks of A oil field is immature and didn't charge thise oil field and binak trough charged this oil field and B oil field wasn't charged by Binak trough because of migration barrier. According to Pr/nC17 vs Ph/nC18 diagram, Gadvan and Garu formation in A oil field include type II kerogen and Kazhdomi formation have type II-III kerogen. Depositional environment of Gadvan, Kazhdomi and Garu formation is reducing. Pr/nC17 vs Ph/nC18 ratio in Kazhdomi formation is more than 1, in Garu is 0.32 and in Gadvan is 0.5 and shows that depositional environment of Kazhdomi formation is probably turb swamps, Garu is marine and Gadvan formation environment are intermediate and it also indicates that level of Maturity of Kazhdomi formation is low, and Gadvan and Garu formation are at the peak oil generation window. Pr/nC17 vs Ph/nC18 diagarm of Fahlian formation in B oil field shows type II kerogen that deposited in reduced environment and it has been located in oil window. C29 Sterane vs Tricyclic terpane/Hopane diagram for studied samples shows that effect of algal matters in Kazhdomi, Garu, and Gadvan formations in A oil field was low. Plots of Kazhdomi, Garu and Gadvan samples in C27/C29 triterpane vs C31R/C30 Hopanes diagram and also in C27/C29 sterane vs sterane/Hopanes diagram shows that source rock samples have carbonate-marl lithology. Possible source rocks (Kazhdomi, Garu and Gadvan) samples plot on C2920S(20S+20R) sterane vs C29 αββ/(αββ+ααα) diagram and in DBT/Phen vs C29 steranes diagram shows that Garu formation in A oil field is in the range of oil window but Gadvan and Kazhdomi samples in these oil fields are immature.

 Modeling thermal maturity is widely used in exploration activities. The purpose of this research is thermal modeling, burial history reconstruction and also hydrocarbon potential evaluation in one of the oilfields of Abadan Plain. For this, data from Rock-Eval pyrolysis (56 samples), vitrintie reflectance (5 samples) and region’s stratigraphic data were used. To determine the hydrocarbon potential of source rocks, S1+S2 vs TOC diagram was used. It indicates that Pabdeh and Kazhdomi formations are in poor to excellent range, Gurpi is in very poor to good and Gadvan is in poor to relatively good range. The oxygen Index (OI) and hydrogen Index (HI) indicate that Kazhdomi and Gadvan formations mostly have type II Kerogen; while pabdeh and Gurpi source rocks contain types II and III kerogens respectively. Based on values of Tmax and production index (PI), samples of pabdeh Formation indicate immature to early oil zone, Gurpi and Gadvan formations are in early oil range to main oil zone and the Kazhdomi Formation is in the early to main oil zone. 1D models of two wells were completed using the Easy%Ro method by Petromod 2012 software. The Gadvan Formation in Well-2 has entered oil window in 2648 meters depth almost 11 million years ago and has been located in the main oil zone in 4354 meters depth since 2 million years ago. Kazhdomi Formation has entered oil window in 3122 meters depths since 4.2 million years ago. In the well-4 the Lower Gadvan Formation since 10 million years ago in 2649 meters depths has entered oil window and has been located in the main oil zone in 4318 meters depth since 2 million years ago. The upper Gadvan Formation almost from 6 million years ago has entered eraly oil window and has been located in the main oil zone since 1.5 million years ago. The Kazhdomi Formation in this well has also entered the oil window in 3035 meters depth since 4.3 million years ago and has been located in the main oil zone since 0.16 million years ago. According to the results and the maturity of drilled formations and comparison with studies in adjacent areas seems Kazhdomi Formation is one of the main source rocks for Bangestan reservoir in this field and to determine the source of Fahlian reservoir more studies for deeper possible source rock formations has to be done.

Ramshir oil field is located on 120 kilometer distance from south east of ahvaz. This field concludes from west to shadegan field , from north to maroon and aghajari fields and from south east to ragesefid field. Current study was performed with purpose of investigating and review of problematic shales of pabde and gorpi formations on ramshir oil field and ultimately reaching to optimum drilling mud on 5 and 6 wells. The important facror that should be considered on determination of drilling mud composition is the composition and structure of clay minerals of formations and their close examination. In order of reaching this purpose , there are several approaches but with respect to the connectiuon to oil and oil reserviors matter , on this thesis the Used tools of oil industry including NGS well logging diagrams has been placed as a priority. Also The two methods of X-ray diffraction (XRD) to identify semi-quantitative and qualitative clay minerals and X-ray fluorescence (XRF) has been used. On this study 11 sample from wells of 5 and 6 of ramshir oil field with respect to mentioned methods , were analyzed. The results of performed study showed that on studying NGS diagram , Illite and montmorillonite clay minerals were detectable on pabde and gorpi formations. Qualitive analyses of XRD datas was performed by using X`Pert HighScore software where Minerals of illite, kaolinite, montmorillonite, chlorite and mixed layer were detected. In order of analyses of datas and results of XRF analyses on under study samples , variations of raw and main elements based on depth of SiO2 and Al2O3 was reviewed. The results obtained from XRF analyses also confirms the relative abundance of illite, , montmorillonite, chlorite and mixed layer which this point is the indicator of confirmity of results of XRF and XRD analyses. The amounts of Fe , Mn , V are indicators of Depositional environment of reduction of nitrate to sulfate with average PH (group 2) . the ratio of th/u (from 1 – 7) the the indicator of sea evironment to a Intermediate limit. Thus with respect to identified clay minerals , under study samples are placed in D category and therefore , for drilling of these formations and control of shale Inflation , fresh water mud with appropriate additives (glycerol and low molecular weight glycols) is suggested.

Reservoir compartmentalization is the product of variations in behavior of a reservior through a hydrocarbon field. This variation are due to differenses in reservior dynamic characteristics such as prressure and reservior fluid contacts. The main objective of this study is the determination of effective geological factors responsible for Asmari reservoir sectorizing in Marun field. Fortunately Marun field has near 500 dilled wells in this field, 76 wells that have more data and coverage field were selected this study. From structural aspect, Marun structure is bounded by tow main thrust fault in its north and south flank and Aghagari structure is overthrusted on eastern part of Marun structure. In this study Anhydrite, Sandstone, Carbonate and Clay percentage maps were prepared for all reservoir zone and sectors and also petrophysical maps of porosity, water saturation, Net to gross thickness were prepared. In addition one stratigraphic correlation chart was drawn to show lithological change through the reservoir sectors. Based on lithological and petrophisical maps and stratigraphic correlation chart,sectors 4,5,6 and 7 in central part of the field have better reservoir quality than the other sectors. In this study mud losses also prepared to compare with fracture density maps. As a result they confirm the fracture density maps. To show average lithological, Petrophysical and mud losses value for all reservoir sectors, many histogram charts were made. Finally, it can be mentioned that all 8 reservoir sectors of Asmari reservoir in Marun field are positioned and affected by geological Factors and their related petrophysical parameters, such as lithology changes, fractures distribution, porosity, water saturation and net to grass thickness. So they show different dynamic behaviors(Pressure changes and different fluid contacts)

 In this study oils from Sarvak reservoirs of Marun oilfield in Dezful Embayment and AB Teymour oilfield of Dashteh Abadan have been studied geochemically. To further confirm the data and verity the trend of geochemical results of oils from Sarvak reservoir of Azadegan oilfield was also investigated.
Ratio of Pri/nC17 against Phy/nC18 is less than one and indicating reducing environment for original organic matter. Terrigenous organic matter dominance (Terrigenous Aqueous Ratio, TAR) is increasing from Marun (TAR: 0.18) to AB Teymour (TAR: 0.37) and finally to Azadegan (TAR: 0.83), indicating reduction the sedimentation basin’s depth towards western part of the Dezful Embayment and Dashteh Anadan.The Carbon Preference Index (CPI) also confirms these data. Also, Strane to Hopane ratio, C25/C26 tricyclic terpanes and plots of (20R) C29/C27 versus Pr/Ph, all indicate that primitive organic matter was more from algea type in Marun and AB Teymour in compare to oil from Sarvak ofAzadegan oilfield.
C31Rhopane/C30Hopane ratio, δ13CSat Vs Pr/Ph showed marly carbonate nature for organic matter and depositional environments of the three studied oilfields. Plot of Pr/Ph vs DBT/P also confirmed it while suggested Mesozoic age for their source rocks.
Isomerization and epimerization of C32-hopane and C29-Sterane show that oil in Sarvak reservoir of the studied oilfields are between early oil window to peak oil window vicinity.
Finally can it can be concluded that Sarvak reservoir oil from Marun and AB Teymour oilfields was sourced from more marine OM with more reducing conditions in compare to Azadegan oilfield with more terrestrial organic matter deposited in shallower part of the basin.

 Organic rich shales are the kind of sedimentary rocks that have the potential of being the unconventional source for hydrocarbons if achieved sufficient thermal maturity. Cretaceous to Lower Paleocene Shale formation of Dezful embayment are having extensive distribution with a great thickness acting as the main source rock of the giant oil fields with gas cap. In recent years depletion of conventional resources and increase in demand, forced the oil industry to discover new resources and focus on unconventional resource spatially the shale gases. In this study some basic parameters of shale gas reservoir like total organic carbon (TOC), Kerogen type, thermal maturity, deposit environment, mineralogy, porosity, water saturation, thickness, and depth were investigated in Pabdeh, Gurpi, Kazhdomi and Gadvan formations of south Dezful embayment. To achieve that, Rock-Eval pyrolysis, Vitrinite reflection measurement, complimentary Chromatography analysis, XRD analysis, Petrophysic valuation, core analysis have been done and finally burial history data in PetroMod2012 software, burial history modeling of basin has been performed. The results of the analyses carried out on samples taken from Bibi-Hakimeh, Gachsaran, Pazanan, Kheyr-Abad and Gachsaran oil field and conventional calculations show that Pabdeh Formation has very low thermal maturity and Gurpi Formation has total organic carbon as low as 0.7%. For other formations, evaluation parameters show that the Gadvan and Kazhdomi formations both have the same condition. But the Gadvan Formation according to its Ro data, burial history modeling and Rock-eval data has higher thermal maturity. So it can be concluded that the Gadvan Formation with TOC of above 1%, and maturity of upto 1.35% Ro, type II-III mix Kerogen, brittle mineral over 90%, average porosity of 7.7%, 42% water saturation, the average thickness of 66 m and average depth of 3623, as the most talented formation to act as a shale gas formation in the basin.

 The Azadegan oil field with an area of approximately 900 km² and over 33 billion barrels of oil in place is one of the largest developing oil fields in the world. It is located near the border of Iran and Iraq. In fact, this field is located at 80 km West of Ahvaz city and between Jofeir, Darkhovin and Yaran, oilfields. It’s main reservoirs include the Sarvak, Kazhdumi, Gadvan and Fahliyan formations. The lithology of Sarvak Formation in the Bangestan group (Albian - Turonian), is carbonate and acts as one of the most important hydrocarbon reservoir of the Zagros basin.
This study tried to identify important hydrocarbon zones of Azadegan oil field and also introduced two oil fluorescence and gas chromatography geochemical methods during the drilling process, to review and compare Sarvak Formation in both vertical and horizontal wells in north Azadegan oil field. Later, by using geochemical and drilling data, qualitative and quantitative studies of Sarvak hydrocarbon zones were performed.
Evaluation of rock chips and fluorescence property of crude oil during drilling process, in the initial estimation showed that, Sarvak in the northern part of Azadegan oilfield contains thirteen zones of carbonate lithology. Here the third and sixth zones and to some extent the fourth and fifth zones have potential to produce crude oil. For this reason, In the final evaluation gas chromatography was used to identify and evaluate the quality and quantity of hydrocarbon zones more precisely.
Finally, the results of qualitative and quantitative evaluation of oil fluorescence and gas chromatography, along with well data, showed a high potential for hydrocarbon production with a density of about 19 to 20 degree API crude oil in the Sarvak carbonate reservoirs located in the northern part of Azadegan oil field. Between the third and sixth zones having the greatest potential for heavy crude oil production, it is determined that the later one, due to its higher thickness of the hydrocarbon bearing sector, can act as a better reservoir in the Azadegan oilfield.

The petroleum system includes all of the elements and processes that are essential for hydrocarbon accumulation, thus modeling is an efficient tool for understanding and predicting the petroleum system. The objective of this study is 1D petroleum systems modeling in the Lali and Karun oilfields to determine the maturity level, timing of generation and hydrocarbon expulsion from source rocks (Pabdeh and gurpi) during the time. At first, using graphic well log data, the lithology of formations were defined as codes in order to loading into the software. Based on Rock- Eval pyrolyses, the kerogen of formations are mostly type II and II-III. To determine the hydrocarbon potential of source rocks, the S2 versus TOC diagram was used. This diagram indicates that hydrocarbon potential for Pabdeh and Gurpi formations mostly poor until fair in Lali and Karun oilfeilds. To determine the maturation of source rocks, the PI versus Tmax diagram was used. This diagram showed that maturity of Pabdeh and Gurpi formations is mostly early oil zone and few main oil zone in Lali and Karun oil feilds.
Organic petrographic studies revealed that samples of these oil fields have low Vitrinite content and most of their organic matters are Liptinites. Also in lali oilfield due to the presence of rework organic matter, the hydrogen index (HI) of the Pabdeh formation has been increased.
To determine the timing of oil generation, the Temperature, Transformation Ration and Vitrinite Reflectance diagrams were used, Transformation Ration diagram indicates that none formations entered oil window in Lali and Karun oilfeilds. According to the Temperature and Vitrinite Reflectance diagrams, in well#20 in lali oil field at a depth of 2600m, sarvak formation reaches the required temperature to enter the oil window since 13 M.y ago. According to the Temperature and Vitrinite Reflectance diagrams, in well#23 in lali oil field at a depth of 2200m, Pabdeh, Gurpi, Ilam and Sarvak formation reaches the required temperature to enter the oil window since 14M.y ago. According to the Temperature and Vitrinite Reflectance diagrams, in well#1 in Karun oil field at a depth of 3600m, Asmari, Pabdeh, Gurpi, Ilam and Sarvak formation reaches the required temperature to enter the oil window since 13 M.y ago. According to the Temperature and Vitrinite Reflectance diagrams, in well#2 in Karoon oil field at a depth of 4200m, Pabdeh, Gurpi, Ilam and Sarvak formation reaches the required temperature to enter the oil window since 13M.y ago.
 

Abadan plain is a structural zone in the southwestern end of Zagros. The recent discovery of hydrocarbon sources in the Abadan plain , such as Azadegan, Yadavaran and Darquain fields, as well as the existence of common fields show the necessity of comprehensive geological and geochemical studies in this structural zone. The aim of this study is to use the isotopic data to compare the oil of various reservoirs (Azadegan, Kushk, Hoseinieh, Darquain, Yaran, and Ab Teymoor), to determine the possible source rock’s for oil production in different fields, and to examine oils according to maturity, organic material type, and sedimentary environment. To this end, initially 52 samples, including 28 bitumen samples and 24 source rock samples, were selected for bulk isotopic analyze, and among these, 49 were chosen for CSIA. The resulting samples after the initial stages, to undergo GC-IRMS analysis. According to the results of the bulk isotopic analysis, the organic material producing all the oil samples deposited in marine and anoxic environment, and the source rock samples except the samples of Gadvan in Azadegan 4 and Hendijan 6 fields, which deposited in a terrestrial environment, were sedimented in a transitional environment. Since the isotopic difference of almost all the oil samples is lower than ‰3, all of them must be of the same family. The results of CSIA show that since the resulting isotopic profiles have a negative slope lower than ‰5, they are prone for a marine and transitional environment. Based on the isotopic difference between these profiles, two groups can be seen, the difference of which is due to different source rock or maturity level. The isotopic analysis of isonoproeids such as Pristane and Phytane also shows the distinction of the oils under study into two separate groups resulting from almost homogeneous organic materials. The oil-source rock correlation implies that the all oils is generated from the Sargelu formation, or a formation with the same isotopic features, and as the reservoirs, especially Sarvak reservoirs, get younger, the possibility of interfering of the other source rocks such as Garau and Kazhdomi increases. The oil-source rock correlation also indicates the high similarity of the oils under study regarding the source rock and their difference regarding maturity and other secondary processes. Because of its flatter isotopic profile, the oil of the Fahlian reservoir in the Kushk field is produced from more mariner organic materials compared to other samples. In general it can be said that the Sargelu formation is the most important source rock in Abadan plain, and nearly all the oils of this region are belong to the same family. Finally, compare the BSIA and CSIA showed that the results of these two methods are similar, but the accuracy of the CSIA method is much higher.

Comparison of lithological effects on geochemical properties of different oil fields provides better understanding of genesis and source rock which can be used in proposing suitable solutions reservoir characterization and exploration plans.
Asmari reservoirs in maroun , mansouri and ahvaz oil fields were investigated in dezful embayment. Then geochemical data of asmari oil reservoirs were compared to their source rock lithology. To do that, preliminary analyses were conducted including asphaltene removal and column chromatography followed by complementary analyses using gas chromatography (gc) and gas chromatography-mass spectroscopy (gc-ms). The results indicate that the effects of lithology on geochemical properties has resulted in oils with abundant c29 esterane compared to c28 and c27 in maroun field and c14-c20 oils in ahvaz field. Furthermore, geochemical analyses in mansouri oil field shows that c31/c30hopan are more abundant than c26/c27 tricyclic tripans. Therefore , it can be stated that lithology had significant effects on geochemical properties of these oil field.
Most of the data proves the marine origin of source rocks in all of the three fields and small differences in geochemical properties can be attributed to different migration paths, temperature and reservoir conditions. However , based on similar lithological data in the area and its conformity to the obtained geochemical data, it can be concluded that the source rock has marine origin and is the same in all of the fields.
 

Knowledge of petroleum system and hydrocarbon source rocks and recognition of petroleum and gas property in explored structure in Dasht Abadan always had been proposed as an exploratory target. Comprehensive geochemical study on various reservoir horizons and also probable source rocks can be useful in Better recognition of regions and forecast of exploratory target in future. Identifying the Source rocks of Yadavaran, Darquain and Omid oil fields, and also study of Yadavaran and Darquain’s oil samples is the goals of this research. Rock Eval data show that kazhdumi formation in these oil fields has high hydrocarbon potential. According to Tmax versus HI and PI diagrams, Pabdeh, Gurpi and kazhdumi formations are immature; Gadvan formation in Darquain-1 and Hosseinieh-1 wells is in beginning of oil window and in other wells is immature. Garau and Sargelu formations in this oil fields are in oil window. According to GC data, Kazhdumi formation has II-III kerogen type and anoxic depositional environment. Gadvan and Sargelu formations have II kerogen type but Garau has II-III kerogen type and all of these formations deposited in anoxic environment. The GC data show anoxic carbonaceous environment and II kerogen type for oil samples. The star diagrams of normal alkanes ratios show that the oil samples have same source rock. The triangle diagram of steranes show depositional environment among open marine and paralic environment for precursor’s oil samples. The low values of moretane/hopane ratio indicate low entrance of terrestrial organic matter to depositional environment of oil’s source rock. Gamaceran index and sterane/hopane ratio respectively indicate low salinity environment and bacterial source organic matter for oil samples. C29/C30 hopane ratio vs C35/C34 hopnae show carbonate-marl source for oil samples. MDPT/MP vs Pr/Ph ratio indicate marine carbonat-marl source rock for oil samples. According to maturity typical biomarker, Fahlyan reservoir’s oil samples maturity are more than Gadvan and Sarvak reservoir samples. Early production of NSO compounds from low mature source rock can be a reason for Sarvak’s heavy oils. The studied oils have age of Jurassic and lower cretaceous and probably Garau Formation with age of late jurassic and lower cretaceous is their source rock. However migration of Iraq’s oil kichen from Sulaiy Formation with age of late jurassic and lower cretaceous as well as Yamama Formation with age of lower cretaceous have been effect in Iran’s oil fields filling.

The geochemical studies are the early programs in the exploration surveys to reduce the drilling risk. The aim of this study is the geochemical evaluating of probably source rocks in the Omid, Darquain and Khorramshahr oilfields. In this study 65 drilled cutting samples from 5 exploratory wells, well numbers 1, 2 and 3 from Omid oilfield and well number 1 from Darquain and Khorramshahr oilfields, were analyzed by geochemical methods. For supplementary study on candidate formation, samples from Sargalu, Garu, Gadvan and Kazdumi formations, were analyzed by Gas chromatography device. In the studied oilfields, the dominant kerogen in the Garu, Gadvan, Kazdumi and Gurpi formations are type II, IV, II and III respectively. In the studies cross section, in Gadvan and Gurpi formations from North East to South West Abadan plan there wasn’t significant change in the type of kerogen. Also in the studied cross section in Kazdumi formation (from North east to South west) there was obviously change of kerogen type from II to III. Finally it can be concluded that Garu Formation with having a good hydrocarbon potential and maturity is the main source rock in the studied oil fields. And other formations despite fair potential, didn’t have a significant role in hydrocarbon production because of low maturity.

The petroleum system includes all of the elements and processes that are essential for hydrocarbon accumulation, thus modeling is an efficient tool for understanding and predicting the petroleum system.
The objective of this study is 2D petroleum systems modeling in the Aghajari and Pazanan oilfields to determine the maturity level, timing of generation and hydrocarbon expulsion from source rocks (Pabdeh, Kazdumi and Garu) during the time.
At first, a 124 Km cross section was made using graphic well log data and Rockwork software. Bottom Hole Temperature (BHT) data were corrected using Waples formula and the lithology of formations were defined as codes to loading into the software.
The Pabdeh Formation in the Pazanan and Aghajari oilfields is considered to be an excellent potential source rock, with TOC value between 1 to 5% and HI value between 400 to 500 mgHC/grTOC. The Kazdumi Formation is an organic rich (TOC=1-4%) source rock with fair hydrocarbon potential (HI=300-400 mgHC/gr TOC). It’s Tmax (435 to 447) and Ro (between 0.7 to 1%) data show that this formation is in the catagenesis stage and considered to be an active source rock. The Garu Formation by having a variable value of TOC (0.5 to 1.5%) and low value of Hydrogen Index (HI<200 mgHC/grTOC) shows a low potential as a source rock, probably due to the influence of thermal maturity (Ro=1-1.3%). According to temperature and Vitrinite Reflectance data, the amount of Heat Flow (HF) in the Aghajari and Pazanan oilfields is calculated ranging from 46 to 54 mW/M2 and so, HF in the margins and between the two oilfields is more than other parts.
The Pabdeh Formation has entered to oil generation window in Aghajari and Pazanan oilfield about 5-7 and 6-7 million years ago respectively (Vitrinite Reflectance 0.48 to 0.55 percent and Transformation Ratio (TR) above 10 percent) and it hasn’t entered to oil generation window in middle part of Aghajari oilfield. But in middle part of the Pazanan oilfield, Pabdeh source rock has arrived to oil generation window in about 3 to 5 Mya. In the Pazanan oilfield margin and between the anticlines (especially in southern east nose), the maturity of Pabdeh Formation has showed higher amount than other part. Kazdumi Formation, in meddle part of Aghajari and Pazanan oilfield, has entered to oil generation window 18 to 20 and 24-26 years ago respectively (Ro 0.55 to 0.6 percent and TR above 10 percent) and 24-25 and 28-30 million years ago (Ro 0.7 to 0.85 percent and TR above 50 percent) in margin and it locate in oil generation window now. Expulsion of hydrocarbon from the Kazdumi source rock has started in 6-8 and 8-10 million years ago in middle part of Aghajari and Pazanan oilfield respectively 8-10 and 10-11 in margin part (Ro 0.65 percent and TR above 30 percent).
The Garu source rock has entered to the oil window, in the center of the Aghajari and Pazanan oilfields respectively about 91 to 93 and 94 to 96 Mya and in the margins of these oilfields respectively 96 to 98 and 94 to 96 Mya (Ro=0.5% and TR>10%). The onset of oil expulsion from Garu source rock in the center of the Aghajari and Pazanan oilfields is respectively 23 to 25 and 33 to 35 Mya and in the margin of these oilfields is respectively 45 and 38 to 40 Mya. The Garu formation in the mentioned oilfields is now in the peak of gas generation window (Ro=1-1.2%).
Thermal maturity value decreases from the northwest of the Aghajari oilfield to the center and increases from the center of this oilfield to the border of two oilfields, then decreases from their border toward the center of the Pazanan oilfield, then increases to the margin.
 

The Azadegan oil field with more than 33 billion barrel oil in place is one of the world's developing giant oil field with about 900 km2 extent is located at 80 km west of Ahvaz City. More than 80% of this oilfield reserved is in the Sarvak Formation with Carbonate lithology.
Petrophysical studies in carbonate reservoirs due to their heterogeneity have a great importance. In this research Sarvak reservoir in the Azadegan oilfield has been studied petrophysically and geochemically. The purpose of this study is geochemical investigation of the Sarvak reservoir as well as determination of trend variations in the basic petrophysical parameters such as shale volume, total porosity, effective porosity, water saturation, movable hydrocarbon volume, fluid contacts and zonation.
So, to achieve optimum values of calculated water saturation and effective porosity, simultaneously Determine and Probable (multimin) methods were applied. Then after comparing the results, Probable methods was chosen as the interpretation way.
Water saturation was calculated by various method and results show that zones with high shale volume, Indonesia method has more accuracy than Archie’s method, while in clean zones the results of the two methods are similar. To obtain optimum values of the cementation coefficient in Archie formula, coincidently the three methods of Picket, Shell and Borai were used and the values given in Borai method was chosen.
The important point in this research is performing the sensitivity analyzing to determine the effective cutoff of the porosity and water saturation locally, unlike given Master development Plan (MDP) which calculate it generally. Our result is more efficient in optimum production than MDP.
Oil-water contact with petrophysical logs and Repeated Formation Test (RFT) evaluation in the depth of 2893.5 m as well as oil and water pressure gradient with the values of 0.394 psi/f and 0.51psi/f respectively were obtained.
Sterane/Hopane and Terrigenous/Aqueous Ratios (TAR) shows that the source rock for studied reservoir’s oil enriched by organic matter from mixed (bacterial and algal) source and contribution of bacterial source in north part is high. High amount of C29/C30 Hopane and DBT/Phen ratio shows that the source rock of Sarvak reservoir’s oil derived from carbonate source rock in marine environment.
Presence of tricyclic terpanes, zero value of Oleanane/(Oleanane+Hopane), and δ13C Vs Pr/Ph diagram show source rock of Sarvak reservoirs is carbonated with Jurassic to lower Cretaceous age. Isomerization and epimerization of C32-hopane and C29-Sterane show that oil in Sarvak reservoir is located in the early Peak Oil Window.
Finally Based on Petrophysical parameter, Sarvak Formation was divided to 13 zones which among these 3, 5 and 6 were introduced as the best reservoir zones. Net pay, average effective porosity, average water saturation and net pay/gross ratio for each zone were calculated and based on the given results water saturation to the north part is increased while average effective porosity is decreased. Geochemical results show Sarvak reservoir oil is derived of source rock with carbonated lithology older than Cretaceous in age.
 

Finding applicable methods to reduce the exploration costs and save time can help the exploration for hydrocarbon resources. This requires a detailed study and evaluation of potential source rocks. Total organic carbon and thermal maturity are among the most important geochemical factors to source rock assessment. In source rocks with sufficient quantity of organic matter, thermal maturity is an essential factor that define the hydrocarbon potential.Thermal maturity is an index to determine the maximum temperature that the source rock endured at the different stages of basic evaluation. This parameter can be estimated by different geochemical methods. In this study, in order to estimate thermal maturity of the Kazhdomi Formation in the Jufair oilfield (Abadan plane) vitrinite reflectance and Tmax data were used. Considering the general scarcity of measured maturity data in exploration area, development of a new method for direct estimation of this parameter from well log and seismic data was made as the objective of this study. In this method, using well logs such as neutron, resistivity, sonic and density, the maturity of the studied source rock was calculated via Maturity Index Equation at well location (3 wells) These calculated values were then used as inputs for a Multi Attribute Analysis to find a logical relation with seismic attributes.

In this study inversion of seismic data was performed based on Model-based Algorithm because of its high accuracy, and the resulting acoustic impedance was utilized as an external attribute to estimation of Maturity Index. Acoustic impedance showed the highest correlation coefficient with Maturity Index and was selected as the optimal attribute. Finally Maturity Index was estimated using seismic attributes with correlation coefficient of 95%. The results of this study can be used for assessment of changes in thermal maturity of Kazhdomi Formation throughout available 3D seismic volume, and also to determine the appropriate places for sampling in future geochemical analysis. In addition, measured maturity values can be extrapolated with a higher degree of accuracy to the undrilled areas of the studied oilfield.

Calculations showed that Kazhdomi Formation in the studied oil field with Maturity Index value ranging from 8 to 11 is in the oil window. Also calculated Maturity Index profiles from seismic data showed that Kazhdomi Formation has higher level of thermal maturity in the southern flank of anticlines than other parts probably due to deeper burial.
 

Abadan Plain is located in southwest of Iran including the northern parts of Persian Gulf. This sedimentary basin has the second largest oil concentration in Iran after Dezful Embayment. The main objective of this study is to determine the geochemical characteristics of organic matter in Sargelu, Garau, Gadvan, Kazhdumi, Gurpi and Pabdeh Formations and evaluate their hydrocarbon generation as possible source rocks in the Abadan Plain. Based on Van-Krevlen diagram, kerogen samples of Sargelu Formation have been mainly designated as type II, suggesting a marine reducing condition with abundant algal organic matter in the sedimentation environment. Due to its high concentration of organic matter, Sargelu of Azadegan and Darquain Oil Fields have Good to Very Good hydrocarbon potential. Furthermore, based on Hydrogen Index (HI) vs Tmax diagram, by entering the catagenesis phase, this formation has entered the oil production zone as the possible source rock. Based on abundant organic matter and maturity, Garau Formation of Jufair and Darquin Oil Fields have high Total Organic Carbon (TOC) and Tmax values and have entered the oil window. Due to its high Tmax, this formation had probably no role in hydrocarbon generation in Azadegan Oil Field. The highest amount of TOC in Kazhdumi Formation are observed in Mahshahr and Hendijan Fields having 4.3% and 3.3% respectively. This indicates Very Good hydrocarbon potential of this formation in these fields. HI and Oxygen Index (OI) of kerogen organic matter, have categorized its kerogen content as type II and II-III and in some fields as IIS to II-III. Moreover, based on organic matter quality, it has oil and gas production potential. It also indicates that Kazhdumi Formation had reducing to intermediate sedimentation environment. This formation has characteristics of a source rock in terms of organic matter and being in the oil window in AT, JF, SPH, AVD, OD, KM, MR and Azadegan7 Fields. However, due to less maturity, it is considered an immature source rock in other fields. In all of the studied fields in Abadan Plain, Pabdeh, Gurpi and Gadvan Formations do not have characteristics of a source rock. Based on high level of organic matter and sufficient maturity, Garau and Sargelou Formations are possible oil source rocks in Abadan Plain Fields, while in SOH, YRN, AZN and HOSS oil fields, they cannot produce oil due to low maturity. Therefore, it is probable that Yamama and Suley Formation charge these oil reservoirs. Finally, given that Kazhdumi formation is conforming to the thermal maturity of Sargelu and Garau Formations, it can be concluded that Kazhdumi Formation is in the range of oil generation in some fields and Garau formation, that is deeper, is most likely in the oil window.

Abstract:
In this study oils from various horizons of Dashte Abadan reservoirs have been compared. Their probable source rocks were identified using appropriate biomarkers. In addition these biomarkers were also used to determine the organic matter type, environment of deposition and the maturity of organic matter using complimentary GC-MC method. To do this 50 samples of rocks from available sources of Pabdeh, Kajdomi, Gadovan, Garu, Sargalu in Azadagan oil fields, Hosseineh, Kushk, Darkhovain, Khoramshahr, Arvand, Hendijan, Sepehr, Jufair, Abteimor, Omid and Bandekarkhe oilfield were studied. The C23 Tricyclic Terpan/C30 Hopane, Sterane/Hpane and the Gammacerane indicate organic materials types, II and II/III. The distribution of sterans C27, C28, C29, the relative amounts of C35S/C34S Hopanes and C29/C30 Hopane and C31R/C30Hopane, tricircle Hopane C26/C25, show that the studied samples are Marine carbonate and shells. The relative Biomarker maturity includes C32 22S/(22S+22R), Moretane/Hopane, C29ββ/(ββ+αα), C29 20S/(20S+20R), Ts/(Ts+Tm), C29TS/(C29Ts+C29hopane). These indicate that the samples of Pabdeh, Kajdomi, and few of Gadovan formations, in Azadagan, Hosseineh, and Kushk oilfields, are immature. On the other hand Kajdomi Formation in Sepehr, Omid, Jofeir, and Khoramshahr oilfields and Garu and Sargalu formations are in oil windows range. The oil samples of Fahlian, Gadovan, Daryan, Kajdomi, Sarvak, Ilam and Gorpi reservois, according to to their Sterane/Hopane, C23 Tricyclic Terpan/C30 Hopane and Gammacerane index show types II and mix II/III kerogens. The distribution of C27, C28, C29 stranes, the relative amounts of C35S/C34S Hopane, C29/C30 Hopane and C31R/C30Hopane and C26/C25 tricyclic terpane, all show that the studied samples are marine carbonate and shells. The relative maturity biomarkers including C32 22S/(22S+22R), Moretane/Hopane, C29 ββ/(ββ+αα), C29 20S/(20S+20R), Ts/(Ts+Tm) and
C29Ts/(C29Ts+C29hopane) indicate that all the oil samples are placed in oil window categories. Also, all the studied oils are in one oil family generated from bacteria in reducing environment. But according to their maturity are devided in two distinct groups. Here, samples from Gadvan, Kajdomi and Fahlian are more mature in compare to Sarvak, Ilam and Gorpi reservoirs. Comparing the thermal maturity between the formations of Garu, Kajdomi, in Iran with that of Yamama and Soleh formations in Iraq, it can be concluded that, these formations have the capability to generate such oils. Finally the cause for heavy oils in Sarvak and Illam reservoirs is most probably the Kazhdumi Formation with appropriate maturity level.
 

 The Abadan plain is located in the most extreme south west of Zagros. The purpose of this study was to geochemically investigate the formations of Garau, Sargelu, Kazhdumi and Gadvan as a potential source rocks. Also to determine the involvement of these formations in hydrocarbon- prodution, examine the existing oils in the reservoirs (Sarvak, Fahliyan, Gadvan) of Abadan plain, specify the type of organic matter, maturity, and to investigate the genetic relationship between oils and their probable source rocks. In this study, 37 samples were pyrolized simultaneously along with gas chromatography (PY-GC), 73 samples of bitumen and 35 samples of oil were also analyzed by GC. The Pr/nC17 diagram against Ph/nC18 and parameters of Pr/Ph، CPI، Waxiness، TAR indicate that the depositional environment was semi-oxidant with low maturity Kerogens of Type III and mixed type II-III of pabbdeh and Gurpi formations. Also, these parameters represent marine organic matter of Gadvan Formation and a mixture of marine and terrestrial organic matter of Kazhdumi, Garau and Sargelu formations. The maturity of Kazhdomi Formation varies between immature to mature, such that the highest maturity was seen in the north Azadegan, Sepehr, AbTeimor, Omid, Mahshar oil fields, whereas in the south Azadegan and Hendijan oilfield the maturity of this formation is low. Maturity of Gadvan Formation is in the range of the oil window, while its highest maturity is in the Azadegan and the lowest in the Hendijan oil fields. The highest maturity of Sargelu Formation is in the Darkhoein and Jufair oil fields while the lowest maturity is obtained in the Hendijan and south Azadegan oilfields. The gas chromatography of oil samples indicate that in all the Abadan plain reservoirs their organic matter source was of marine origin. Given the maturity variation, the Abadan plain reservoirs can be classified in two groups: highly matured ( Fahlyian, Gadvan and Kazhdumi) and with low maturity (Sarvak, Darian and Ilam). The said GC parameters indicate that the oil in the Sarvak reservoir may be in the early stages of maturity and ha lower maturity in compare to Fahyian and Gadvan reservoirs. Also, it is likely that the Kazhdomi Formation in more mature reservoirs has played a role in charging Sarvak reservoir. Due to the low maturity of Garau and Sargelu formations in the western Abadan plain, and similarity of oils with that of Iraqi Mesopotamian basin, it can be concluded that, the Sulay and Yamama formations must have charged western part reservoirs of Abadan Plain. On the other hand since, Kazhdumi Formation is matured, therefore, Garau Formation must have been fully matured and has charged the reservoirs with hydrocarbons in the eastern part of Abadan Plain.